Method and Apparatus for Separating and Measuring Multiphase Immiscible Fluid Mixtures

ABSTRACT

An automated process and accompanying apparatus simultaneously separates and measures the flow rate of any multiphase mixture of immiscible fluids. Such separation and measurement can occur in a single vessel, or multiple vessels. Liquid levels, together with a material balance analysis, are utilized to determine constituent liquid flow rates. The vessel(s) can be remotely operated and monitored in real time, while also allowing for automated or manual calibration.

CROSS REFERENCES TO RELATED APPLICATION

THIS APPLICATION IS A CONTINUATION OF U.S. NON-PROVISIONAL patentapplication Ser. No. 15/606,307, FILED May 26, 2017, CURRENTLY PENDING,WHICH CLAIMS PRIORITY OF U.S. PROVISIONAL PATENT APPLICATION Ser. No.62/341,707, FILED May 26, 2016, AND U.S. PROVISIONAL PATENT APPLICATIONSer. No. 62/447,990, FILED Jan. 19, 2017, ALL INCORPORATED HEREIN BYREFERENCE.

STATEMENTS AS TO THE RIGHTS TO THE INVENTION MADE UNDER FEDERALLYSPONSORED RESEARCH AND DEVELOPMENT

NONE

BACKGROUND OF THE INVENTION 1. Field of the Invention

The present invention pertains to an apparatus and associated method forseparating multiphase fluid mixtures into separate phases (gas andliquid), while measuring certain constituent components of said fluidmixtures. More particularly, the present invention pertains to anapparatus and method for separating a bulk production stream from ahydrocarbon producing well into separate phases (gas and liquid),separating liquid hydrocarbons from water, and independently measuringproduced volumes of said liquid hydrocarbons, gas and/or water. Moreparticularly still, the present invention pertains to an apparatus andmethod for meterless measurement of a bulk production stream from ahydrocarbon producing well, with continuous calibration of suchmeasurement and no interruption of operations for such calibration.

2. Brief Description of the Prior Art

Accurate measurement of multiphase immiscible fluid mixtures is requiredin many different applications and settings. One such common applicationis the measurement of fluids produced from subterranean wells, such asoil and/or gas production wells. In many cases, bulk production fromsuch wells comprises a multiphase stream of immiscible fluids comprisinga mixture of liquid hydrocarbons (such as crude oil or condensate),formation water and natural gas. Often, such natural gas can be “free”gas, while in other cases such gas can be released from solution whenliquid hydrocarbons are produced from a subterranean formation to theearth's surface.

Typically, such produced fluids must first be separated into differentphases (i.e., gas and liquids) prior to disposition of such gas. Suchgas should typically have very little, if any, liquid components priorto flaring or venting of the gas into the surrounding atmosphere, ordelivery of the gas to a transportation pipeline. Many gastransportation pipelines limit the volume of liquids that can bedelivered into said pipelines with such gas, while gas flaring andventing operations can be can negatively impacted by the presence ofexcess liquids in a gas stream.

Similarly, produced liquids—which frequently comprise an immisciblemixture of liquid hydrocarbons and formation water—typically must alsobe separated prior to disposition. Liquid hydrocarbons generally must beseparated from formation water before such liquid hydrocarbons can betransported from a well site for ultimate use or sale. Many crude oilpurchasers and/or transporters will not accept significant volumes offormation water with such oil. Similarly, separated formation water,which is typically re-injected into a disposal well or trucked toanother location for disposal, should include little or no residualliquid hydrocarbons; such liquid hydrocarbons typically have value thatcan be realized, and their presence with produced water can frequentlynegatively impact water disposal operations.

Conventional methods of separating produced fluids from oil and/or gaswells typically involve separation of multiphase fluids into gas, liquidhydrocarbons and/or formation water components in a series of(frequently pressurized) vessels. Gas is first separated from liquidcomponents in one vessel, while said liquid components (liquidhydrocarbons and formation water) flow to another vessel and areseparated from each other. Separated liquid hydrocarbons are sent to yetanother vessel or isolated tank, while the separated formation water isstored for subsequent disposal or injection.

Accurate measurement of liquid hydrocarbons and formation watercomponents is frequently difficult and unreliable using conventionalmeans. Typically, flow meters (turbine meters or other type meters) areused to measure each distinct fluid stream—that is, a separate meter isrequired to measure liquid hydrocarbons formation water. However, suchfluid flow meters can be expensive and are frequently inaccurate.Further, such conventional meters are generally labor intensive andcostly because they require frequent calibration, and do not provide anyalarm or warning if/when said meters are out of calibration (leavingpossible unknown error between calibration events, which can be 3 to 6months apart or more).

Conventional separator devices simply fill up with production liquids(oil and water) and then dump through a turbine meter periodically whichresults in a series of slug volumes measured by said turbine meter. Asnoted above, said meters can be notoriously inaccurate and difficult tokeep calibrated. Moreover, for a relatively low rate well, a vessel maynot fill up with enough liquid to trigger a dump; as a result, nothingwould go through the meter and the daily production rate could beerroneously assumed to be zero, even though said well may have actuallyproduced some liquids into the vessel (but just not enough to trigger adump).

Thus, there is a need for a cost-effective means for efficientlyseparating multiphase immiscible fluid mixtures (such as, for example,bulk fluids produced from an oil well) into liquid hydrocarbons, gaseouscomponents and formation water, while simultaneously providing foraccurate measurement of said fluids, all without the use of conventionalflow meters and multiple vessels. Such measurement should provide forcontinuous measurement calibration or independent confirmation, as wellas an alarm or warning if calibration variance exceeds a predeterminedamount, all with no downtime or interruption of operations to performsuch calibration/confirmation. Further, such measurement shouldcontinuously account for every molecule of oil and water even if it doesnot dump any liquids during a designated production period.

SUMMARY OF THE INVENTION

The present invention generally comprises an automated process andaccompanying apparatus for simultaneously separating and measuring anymixture of immiscible fluids including, without limitation, multiphasefluid mixtures. The method and apparatus of the preferred embodimentprovides for continuous separation and measurement of such fluids in atleast one vessel, with no downtime (i.e., cessation of such separationand/or measurement operations) required for dumping or evacuation offluids from said at least one vessel.

In a preferred embodiment, the present invention beneficially comprisesa single vessel having a predetermined geometry and dimensions, anddefining an internal chamber. Said internal chamber is divided into aplurality of separate compartments. Each compartment is equipped with atleast one liquid level sensor and at least one flow conduit in fluidcommunication with said compartment. Automated valves, in operationalengagement with said level sensors, permit selective fluid equalizationbetween certain compartments via said conduits, as well as selectivedumping or evacuation of fluids from certain compartments.

A multiphase mixture of immiscible fluids is introduced into a firstcompartment of said vessel. Gas and liquid phases of said mixture areseparated from each other, while immiscible liquids are furtherseparated into different compartments. Liquid levels within eachseparate compartment are continuously measured using said liquid levelsensors; said liquid level sensors may be direct and/or indirectsensors, and may be mounted internally or externally relative to saidvessel. Such liquid level measurements (determined by said liquid levelsensors), together with material balance analysis, are utilized todetermine liquid volumes within each compartment at any given time.Automated valves, operationally engaged with said liquid level sensors,permit fluids within each compartment to be separately evacuated whendesired.

The method and apparatus of the present invention can generallyrepeatedly progress through multiple “phases” to facilitate continuousoperation. In a preferred embodiment, said phases comprise: fill-up,pre-dump stabilization, dumping, post dump stabilization, andequalization phases; however, it is to be understood that theaforementioned phases can be altered or modified in some respectswithout departing from the scope of the present invention.Notwithstanding the foregoing, fluid volumes can be measuredcontinuously and are not dependent upon or a function of completion ofany particular phase.

The vessel of the present invention can operate at a wide variety oftemperatures and pressures, both naturally and/or artificially induced;when desired, operating temperature and/or pressure can be beneficiallyadjusted to facilitate the separation of the total fluid system intodifferent phases and components, as well as evacuation of fluidcomponents from said vessel following a rate measurement cycle or otherdesired interval.

Machine vision, utilizing camera(s) and associated processor(s), canalso be used for primary liquid level measurement, secondary or backupliquid level measurement, and/or calibration or confirmation of aprimary liquid level measurement system, as more fully described herein.By way of illustration, but not limitation, external sight-glasses canbe provided for each compartment (typically with a visible scale orother distance marker), thereby allowing visual identification anddetermination of each fluid or fluid interface level for eachcompartment. Such fluid level information obtained using suchsight-glasses or other level measuring device(s) can then be used forprimary fluid volume measurement, or as a secondary fluid level sensorfor back up measurement purposes.

When used as a secondary fluid level system, such sight-glass levels canbe used for periodic manual calibration or confirmation, or continuousautomated calibration or confirmation, of primary level sensors. Suchcontinuous or automated calibration or confirmation can be performed bycontinuously monitoring and/or sensing sight-glass levels using anymeans capable of distinguishing such liquid level(s) and providing adigital signal of such level(s) such as, for example, machine visioncamera systems, guided wave radar and/or bar code reading devices.Manual calibration and/or measurement confirmation can be performedperiodically (for example, daily) by existing operations or fieldpersonnel without specialized training; volumes can be quickly andeasily calculated using sight glasses and scales/rulers, and suchvolumes can be compared to volumes measured using a primary fluid levelsystem.

Additionally, an alarm system can provide audible or visual signals,and/or send digital transmissions or SMS text alerts, in the event thatsuch secondary readings are outside of a predetermined variance comparedto levels measured and/or volumes calculated using a primary fluid levelsensor system.

The apparatus of the present invention can be remotely operated andmonitored in real time, while also allowing for automated or manualcalibration. Sensors to measure temperature, pressure and gaschromatograph analysis, oil gravity, and/or oil basic sediment and watercan also be added to provide further detail to results.

BRIEF DESCRIPTION OF DRAWINGS/FIGURES

The foregoing summary, as well as any detailed description of thepreferred embodiments, is better understood when read in conjunctionwith the drawings and figures contained herein. For the purpose ofillustrating the invention, the drawings and figures show certainpreferred embodiments. It is understood, however, that the invention isnot limited to the specific methods and devices disclosed in suchdrawings or figures.

FIG. 1 depicts a side schematic view of a fill-up phase or stage of thepresent invention.

FIG. 2 depicts a side schematic view of a pre-dump stabilization phaseor stage of the present invention.

FIG. 3 depicts a side schematic view of a dumping phase or stage of thepresent invention.

FIG. 4 depicts a side schematic view of a post-dump stabilization phaseor stage of the present invention.

FIG. 5 depicts a side schematic view of an equalization phase or stageof the present invention.

DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT

The present invention comprises an automated process and accompanyingapparatus for simultaneously separating immiscible fluids including,without limitation, multiphase fluid mixtures, and measuring componentsthereof. The present invention is discussed herein primarily in thecontext of oil and gas operations, and the separation of multiphasefluid mixtures produced from subterranean oil and/or gas wells. However,it is to be observed that the method and apparatus of the presentinvention can be beneficially utilized in connection with otherapplications requiring the efficient and effective continuous separationand measurement of multiphase immiscible fluid mixtures.

In a preferred embodiment, the present invention comprises a singlevessel which can be used to separate a bulk mixture of oil, gas andwater (including emulsions) into its individual components, and tomeasure the respective volume of each such separated component. Further,the method and apparatus of the present invention provides forcontinuous separation and measurement of such fluid production, withlittle or no downtime (i.e., cessation of such separation and/ormeasurement operations) required for dumping or evacuation of fluidsfrom said vessel. As used herein, the term “oil” shall be understood tomean any liquid hydrocarbon including, without limitation, crude oil,condensate, natural gas liquids, other hydrocarbon compound orcombinations thereof.

Referring to the drawings, FIG. 1 depicts a side schematic view ofvessel 10 (depicted during a fill-up phase or stage, discussed in detailbelow). In a preferred embodiment depicted in FIG. 1, vessel 10comprises a substantially horizontal container defining an internalchamber 11. Internal baffle 12 and divider 13 partition said innerchamber 11 into a plurality of discrete compartments. Although otherconfigurations can be envisioned without departing from the scope of thepresent invention, internal baffle 12 and divider 13 cooperate to divideinternal chamber 11 into three separate compartments: bulk separationcompartment (denoted “A” on FIG. 1), water isolation compartment(denoted “B” on FIG. 1) and oil isolation compartment (denoted “C” onFIG. 1).

In a preferred embodiment, baffle 12 does not extend the entire distancebetween lower wall or bottom 14 and upper wall or top 15, of vessel 10;however, it is to be observed that said baffle 12 could extend frombottom 14 to top 15 of vessel 10, so long as appropriate equilibriumpiping or conduit allowed for oil flow between bulk separationcompartment A and water isolation compartment B. By contrast, in theembodiment depicted in FIG. 1, divider 13 does extend the entiredistance between said bottom 14 and top 15. As such, oil isolationcompartment C is completely isolated from bulk separation compartment Aand water isolation compartment B within internal chamber 11 of vessel10. It should also be observed that bulk separation compartment A, waterisolation compartment B and oil isolation compartment C, or combinationsthereof, could alternatively comprise separate vessels without departingfrom the scope of the present invention, provided that said compartmentsare all maintained in volumetric equilibrium using any necessarypiping/conduits.

Gas outlet port 21 in water isolation compartment B and gas outlet port22 in oil isolation compartment C extend through upper wall or top 15 ofvessel 10 and lead to gas conduit or flow line 20 equipped with pressurerelief valve 23. Said gas flow line 20 can extend to a gas pipeline,sales meter, flare assembly or venting assembly (not shown in FIG. 1),all well known to those having skill in the art, for ultimatedisposition of natural gas. Further, an orifice meter or other measuringdevice can be provided on said flow line 20 in order to measure gasvolumes passing out of vessel 10 through said gas flow line 20.

Vessel 10 of the present invention can operate at a wide variety oftemperatures and pressures, both naturally and/or artificially induced.When desired, operating temperature and/or fluid pressure withininternal chamber 11 can be beneficially adjusted to facilitate theseparation of the total fluid system into different phases andcomponents, as well as evacuation of fluid components from said separatecompartments. Although not depicted in FIG. 1, adjustable heatingelements can be utilized to adjust the operating temperature of vessel10 and any fluids contained within internal chamber 11, while a gascompressor can be utilized to increase fluid pressure within saidinternal chamber 11.

At least one liquid level sensor is provided within each discretechamber in vessel 10. In the embodiment depicted in FIG. 1, liquid levelsensors 30 and 31 are provided in bulk separation compartment A, liquidlevel sensors 40 and 41 are provided in water isolation compartment B,and oil liquid level sensor 50 is provided in oil isolation compartmentC. In a preferred embodiment, said liquid level sensors each measure theupper level of liquids contained within their respective compartmentsrelative to bottom wall or base 14 of vessel 10, as more fully set forthherein. For example, as depicted in FIG. 1, liquid level sensor 30measures the upper level of water and the oil/water interface, whileliquid level sensor 31 measures the upper level of oil and the oil/gasinterface, in bulk separation compartment A. Similarly, liquid levelsensor 40 measures the upper level of water and the oil/water interface,while liquid level sensor 41 measures the upper level of oil and theoil/gas interface, in water isolation compartment B. Oil liquid levelsensor 50 measures the upper level of oil and the oil/gas interface inoil isolation compartment C.

First water outlet port 32 extends through bottom wall or base 14 ofvessel 10 within bulk separation compartment A and connects to firstwater conduit or flow line 33 having automated liquid control valve 34.Second water port 42 extends through bottom wall or base 14 of vessel 10within water isolation compartment B and connects to second waterconduit or flow line 43 having automated liquid control valve 44. Saidfirst water flow line 33 and second water flow line 43 are in fluidcommunication with water evacuation flow line 60 which is equipped withautomated liquid control valve 61. Evacuation flow line 60 can extend toa water storage tank, pipeline or disposal/injection well (not depictedin FIG. 1), all well known to those having skill in the art, forultimate disposition of said produced water.

First oil conduit or flow line 53, having upper inlet port 52 andautomated liquid control valve 54, extends through bottom wall or base14 of vessel 10 within water isolation compartment B; said oil conduit53 could also be mounted externally without departing from the scope ofthe present invention. Oil outlet port 55 extends through bottom wall orbase 14 of vessel 10 within oil isolation compartment C and connects tosecond oil conduit or flow line 56 having automated liquid control valve57. Said first oil flow line 53 and second oil flow line 56 are in fluidcommunication with oil evacuation flow line 70 which is equipped withautomated liquid control valve 71. Oil evacuation flow line 70 canextend to an oil storage tank, pipeline or lease automated custodytransfer “(LACT”) meter (not depicted in FIG. 1), all well known tothose having skill in the art, for ultimate disposition and/or sale ofsaid produced oil.

As noted above, liquid levels within each separate compartment A, B andC are continuously measured using direct and/or indirect liquid levelsensors; said liquid level sensors may be mounted internally orexternally relative to vessel 10. As depicted in FIG. 1, liquid levelsensors 30, 31, 40, 41 and 50 each comprise buoyant floating elementsthat float on the upper surface of particular liquids, monitor therelative positions of said floating elements within chamber 11, andsignal such information to a remote location (such as a computerprocessor). By way of illustration, but not limitation, said liquidlevel sensors 30, 31, 40, 41 and/or 50 can comprise “Model 1000S”digital tank gauge devices marketed by Advanced Telemetrics, Inc., orother liquid level sensors having similar characteristics andfunctionality.

Such liquid level measurements (determined by said liquid levelsensors), together with material balance analysis, are utilized todetermine liquid volumes within each compartment at any given point intime. Further, such liquid level sensors are operationally engaged withautomated liquid control valves as more fully set forth herein; saidliquid level sensor readings can be converted into digital data whichcan be used, together with at least one computer processor, to controlautomated control valves, such as valves 34, 44, 61, 54, 57 and/or 71.

The volume of a particular liquid in a particular compartment can bevolumetrically calculated using the respective liquid's level in saidcompartment (measured by an applicable sensor), multiplied by a volumeconstant; the volume constant for each compartment is a function of thatcompartment's dimensions and can be calculated using formulas applicableto the compartment's (and vessel's) geometry. Generally, materialbalance is achieved by temporarily isolating water isolation compartmentB and oil isolation compartment C from bulk separation compartment Awhen dumping is triggered for liquid(s) in either compartment B and/or Cas more fully described herein.

The present invention permits measurement of liquid “stock” volumeswithin internal chamber 11 of vessel 10 at any desired point in time.For example, an oil “stock” volume comprises a sum of the oil volumes incompartment A, compartment B and compartment C at any desired point intime. The oil volume in compartment A can be volumetrically determinedknowing the dimensions of compartment A, as well as the height of theoil column in compartment A as measured by the relative positions ofliquid level sensors 30 and 31. The oil volume in compartment B can bevolumetrically determined knowing the dimensions of compartment B, aswell as the height of the oil column in compartment B as measured by therelative positions of liquid level sensors 40 and 41. The oil volume incompartment C can be volumetrically determined knowing the dimensions ofcompartment C, as well as the height of the oil column in compartment Cas measured by the liquid level sensors 50.

A water “stock volume” comprises a sum of the water volumes incompartment A and compartment B (because there is no water incompartment C, no volume from compartment C is included) at any desiredpoint in time. The water volume in compartment A can be volumetricallydetermined knowing the dimensions of compartment A, as well as theheight of the water column in compartment A as measured by liquid levelsensor 30. The water volume in compartment B can be volumetricallydetermined knowing the dimensions of compartment B, as well as theheight of the water column in compartment B as measured by liquid levelsensors 40.

In a preferred embodiment, during a preselected production period, themethod and apparatus of the present invention will typically progressthrough multiple “phases”, all of which together comprise a single cyclewhich can be continuously repeated; said phases generally comprise:fill-up, pre-dump stabilization, dumping, post dump stabilization, andequalization phases. However, it is to be understood that theaforementioned phases can be altered or modified in some respectswithout departing from the scope of the present invention. Productionvolumes can be measured continuously and are not dependent upon or afunction of completion of any particular phase or cycle. As a result,production flow rates for oil (and water, if desired) can be determinedover any desired or predetermined time interval.

Referring to the drawings, FIG. 1 depicts a side schematic view ofvessel 10 depicted during a fill-up phase or stage. In a preferredembodiment, a multiphase mixture of immiscible fluids 100 is introducedinto said vessel via fluid inlet 16. By way of illustration, but notlimitation, said fluid mixture 100 can comprise a bulk production streamproduced from a subterranean oil well generally comprising oil,formation water and natural gas in various proportions (including,without limitation, emulsions). Although said production stream can bepiped into vessel 10 from the outlet of another vessel or storage tank,it is to be observed that said production stream can be piped directlyfrom the outlet flow line of a subterranean well into vessel 10.

Multiphase immiscible fluid mixture 100 enters internal chamber 11 ofvessel 10 via inlet port 16 and is received within bulk separationcompartment A within internal chamber 11 of said vessel 10. Gas andliquid phases of said mixture are initially separated from one another.Such separated gas rises within internal chamber 11, and eventuallyexits vessel 10 via gas outlet port 21 and gas flow line 20. Separatedliquid components of said fluid mixture 100 (oil and water, includingemulsions) remain within bulk separation compartment A. Said liquidcomponents contained within said bulk separation compartment A willfurther gravity separate, with (heavier) water component 120 settling onthe bottom of said bulk separation compartment A and (lighter) oilcomponent 110 floating on said water component 120.

As multiphase immiscible fluid mixture 100 continues to enter internalchamber 11 of vessel 10 via inlet port 16, the overall liquid volume inbulk separation compartment A increases, causing the total liquid levelin said compartment A to rise. Eventually, liquid in compartment A risesto a level higher than divider baffle 12, causing a portion of saidliquid from compartment A to spill or flow over the upper surface ofdivider baffle 12 into water isolation compartment B. In a preferredembodiment, the upper surface of baffle 12 is positioned, andcompartment A is sized for fluid retention purposes, so that only oil(and very little, if any, water) passes over said baffle 12 intocompartment B.

In the configuration depicted in FIG. 1, liquid level sensors 31, 41 and50 sense that the upper level of liquids in each of said compartmentshas not risen to the level of predetermined oil dump level 300. As such,said liquid level sensors 31, 41 and 50 send signals to liquid controlvalves 54 and 57 to remain open, and to liquid control valve 71 toremain closed. Similarly, liquid level sensors 30 and 40 sense that theupper level of water in each of compartments A and B has not risen tothe level of predetermined water dump level 310. As such, said liquidlevel sensors 30 and 40 send signals to liquid control valves 34 and 44to remain open, and to liquid control valve 61 to remain closed.

In this configuration, water from the bottom of water compartment Aflows out of first water outlet port 32, through first water conduit 33,automated liquid control valve 34, second liquid control valve 44,second water conduit 43, second water port 42; in this manner, waterlevels in bulk separation compartment A and water isolation compartmentB are permitted to equalize. Similarly, a portion of the liquid in waterisolation compartment B flows into upper inlet port 52 of first oilconduit 53; because of the location of said inlet port 52 near the upperextent of the liquid level in said water isolation compartment B, saidliquid entering said inlet port 52 is all (or substantially all) oilwith very little, if any, water component. Such oil passes through firstoil conduit 53 and first liquid control oil valve 54, past second liquidcontrol valve 57, through second oil conduit 56 and into oil isolationcompartment C in this manner, oil levels in water isolation compartmentB and oil isolation compartment C is permitted to equalize.

Because such liquid that passes over divider baffle 12 has been (atleast partially) separated while retained within bulk separationcompartment A, which is sized for ideal retention time and oil/waterseparation, and because said liquid generally flows from the uppermostportion of said liquid contained within compartment A, such liquidpassing into water isolation compartment B over divider baffle 12 willtypically contain all or substantially all oil by volume compared toimmiscible fluid mixture 100. Conversely, liquid from the bottom ofwater compartment A transferring into water isolation compartment B viafluid equalization conduits 33 and 43 will typically contain all orsubstantially all water by volume compared to immiscible fluid mixture100. Such liquid contained within water isolation compartment B willfurther gravity separate, with water component 120 settling on thebottom of said water isolation compartment B and oil component 110floating on said water component 120.

FIG. 2 depicts a side schematic view of a pre-dump stabilization phaseor stage of the present invention. As depicted in FIG. 2, liquid levelsensors 31, 41 and 50 sense that the upper level of liquids in saidcompartments has risen to the level of predetermined oil dump level 300.As such, said liquid level sensors 31, 41 and 50 send signals to liquidcontrol valves 54 and 57 to close (and to liquid control valve 71 toremain closed). Similarly, liquid level sensors 30 and 40 sense that theupper level of water in compartments A and B has also risen to the levelof predetermined water dump level 310. As such, said liquid levelsensors 30 and 40 send signals to liquid control valves 34 and 44 toclose (and to liquid control valve 61 to remain closed). Thus, all oiland water automated flow control valves are closed isolating them fromcompartment (A) to stabilize their levels and record their respectivevolumes. This stabilization period can be set to virtually anyacceptable time interval by a user, but is generally accomplished within1 to 3 seconds.

FIG. 3 depicts a side schematic view of a dumping phase or stage of thepresent invention. During said dumping phase, when water is beingdumped, flow control valve 34 is closed, while flow control valves 44and 61 are open, thereby permitting water to evacuate compartment B viaflow lines 43 and 60. The volume of water dumped from compartment Bduring said water dumping phase equals the difference in water stocklevels immediately before and after said water dumping phase.

Similarly, when oil is being dumped (as depicted in FIG. 3), flowcontrol valve 54 is closed, while flow control valves 57 and 71 areopen, thereby permitting oil to evacuate compartment C via flow lines 56and 70. The volume of oil dumped from compartment C during said oildumping phase equals the difference in oil stock levels immediatelybefore, and immediately after, said water dumping phase. During adumping phase, the stock volumes of the respective fluids being dumpedfrom compartments B or C are held constant at the volumes measuredduring the pre-dump stabilization phase while such fluids are beingevacuated from the vessel for calculation purposes.

FIG. 4 depicts a side schematic view of a post-dump stabilization phaseor stage of the present invention, which begins when dumping oil andwater levels reach their dump close levels 320 and 330, respectively.For water, (as depicted in FIG. 4), liquid level sensor 40 senses thatthe upper level of water in water isolation compartment B has reachedits predetermined water dump close level 330. As such, said liquid levelsensor 40 sends a signal to liquid control valves 44 and 61 to close(and to liquid control valve 34 to remain closed).

A similar process occurs during a post-dump stabilization phase for oil.In such instance, as oil level in compartment C falls, liquid levelsensor 50 eventually senses that the upper level of oil in oil isolationcompartment C has reached its predetermined oil dump close level 320. Assuch, said liquid level sensor 50 sends a signal to liquid controlvalves 57 and 71 to close (and to liquid control valve 54 to remainclosed).

With all valves closed on the compartments B and C, a stabilizationperiod occurs; the length of this stabilization period can be set to apredetermined interval by a user but is generally accomplished within 1to 3 seconds. During this period, the post dump water and oil stockvolumes and are measured and recorded and utilized to calculate thedumped volumes for the stage.

FIG. 5 depicts a side schematic view of an equalization phase or stageof the present invention following such post-dump stabilization period.In this phase, the apparatus of the present invention is essentially inthe same basic configuration as depicted in FIG. 1. Namely, liquidcontrol valves 54 and 57 are open, while liquid control valve 71 isclosed. Liquid control valves 34 and 44 are also open, while liquidcontrol valve 61 is closed. In this configuration, water levels in bulkseparation compartment A and water isolation compartment B are permittedto equalize. Similarly, oil levels in water isolation compartment B andoil isolation compartment C is permitted to equalize. The apparatus ofthe present invention remains in this configuration until a pre-dumpstabilization phase (such as depicted in FIG. 2) has been reached assensed by liquid level sensors, at which point the cycle or processrepeats. At all times during the process, bulk fluids can be permittedto flow into internal chamber 11 of vessel 10 via fluid inlet 16; inthis manner, all fluids flowing into vessel 10 are accounted for at alltimes, resulting in material balance.

In operation, the present invention permits measurement of liquid“stock” volumes within internal chamber 11 of vessel 10 at any desiredtime; measurement of said volumes at multiple desired points in timepermits determination of production rate(s) over a desired timeinterval. In this manner, the gross production flow rate for each liquidcomponent is equivalent to the change in stock volume for such liquid,plus the cumulative dumped volumes for said liquid, during a givenchange in time or desired time interval. Although liquid level sensors30, 31, 40, 41 and 50 are depicted as buoyant float sensors, otherliquid level sensors or measurement means can be used in addition to, orin place of, said float sensors. By way of illustration, but notlimitation, external sight-glasses can be provided on vessel 10 for eachcompartment A, B, and C (typically with a visible scale or otherdistance marker), thereby allowing visual identification anddetermination of each fluid or fluid interface level for each suchcompartment. Such sight-glass fluid and/or fluid interface levels can becontinuously monitored and/or sensed using any means capable ofdistinguishing such fluid level(s) and providing a digital signal ofsuch level(s) such as, for example, machine vision camera systems,guided wave radar and/or bar code reading devices, all of which can beoperationally engaged with automated liquid control valves describedherein. When a back-up or secondary fluid level sensing and volumemeasurement system is provided for calibration or confirmation of aprimary fluid level sensing and volume measurement system, an alarmsystem can provide audible and/or visual signals, and/or send digitaltransmissions or SMS text alerts, in the event that such secondaryreadings are outside of a predetermined variance compared to levelsmeasured and/or volumes calculated using said primary system.

Importantly, unlike conventional methods of separation and measurement,the method and apparatus of the present invention does not requiredowntime or delay during vessel dumping or for fluid volume measurementcalibration.

Devices to measure temperature, pressure, oil gravity, oil basicsediment and water (“BS&W”) content and gas chromatograph analysis canbe added to provide further detail to volume measurements. Controlautomation capabilities are also available based on user definedparameters. The present invention can be remotely operated and monitoredin real time, while also allowing for automated or manual calibration.

The present invention uses pumps, gas compressors, externally suppliedgas, gravity flow or combinations thereof. Machine vision, usingcamera(s) and associated processor(s) can be used as part of the presentinvention for primary liquid level measurement, backup liquid levelmeasurement and/or calibration of the primary liquid level measurementsystem as more fully described herein.

Further, the present invention can be used to separate and measure fluidvolumes produced from multiple wells, such as at a multi-wellcommingling facility. In conventional commingling facilities, multiplewells typically flow into a central storage tank or other vessel;commingled production from such central storage facility is collectedand measured prior to sale. The total sales volume is then allocatedback to individual wells/leases based on metered volumes (typicallyusing dedicated separator units equipped with meters) or periodic welltests (typically using at least one shared “test separator”). However,both allocation methods are inherently inaccurate and can result inproduction being erroneously over or under allocated to certainwells/leases.

By contrast, the method and apparatus of the present invention can beused to accurately measure actual production volumes produced from eachwell. With the present invention, each well/lease (or other desiredallocation grouping) can be equipped with the apparatus of the presentinvention. Because all production liquids are accounted for, the sum ofmeasured volumes from such multiple vessels will be equivalent to actualstock tank volumes of all commingled production volumes in a sales tank.Further, such measured volumes can easily be converted to actual oilsales volumes in accordance with standard purchaser requirements usingoil gravity, temperature and pressure data, all of which can be measuredin the vessel of the present invention.

The above-described invention has a number of particular features thatshould preferably be employed in combination, although each is usefulseparately without departure from the scope of the invention. While thepreferred embodiment of the present invention is shown and describedherein, it will be understood that the invention may be embodiedotherwise than herein specifically illustrated or described, and thatcertain changes in form and arrangement of parts and the specific mannerof practicing the invention may be made within the underlying idea orprinciples of the invention.

1. A method for separating and measuring volume of an immiscible wellproduction fluid mixture including oil and water, without metering saidfluid, comprising: a) continuously introducing said immiscible wellproduction fluid mixture into a separation and measurement assemblycomprising a vessel having an internal chamber, wherein said internalchamber further comprises a plurality of compartments havingpredetermined dimensions; b) separating gaseous components from liquidcomponents of said production fluids; c) measuring upper and lowerlevels of oil in each of said compartments at a first time; d) measuringupper and lower levels of water in each of said compartments at saidfirst time; e) volumetrically calculating volumes of oil in each of saidcompartments using said measured oil levels and said predetermineddimensions of said compartments at said first time; and f) summing saidcalculated volumes of oil from each of said compartments.
 2. The methodof claim 1, further comprising: a) volumetrically calculating volumes ofwater in each of said compartments using said measured water levels andsaid predetermined dimensions of said compartments at said first time;and b) summing the calculated volumes of water from each of saidcompartments.
 3. The method of claim 1, wherein said separation andmeasurement assembly further comprises: a) at least one oil level sensorin each of said compartments, wherein each oil level sensor isconfigured to continuously measure an upper level of oil in acompartment; and b) at least one water level sensor in each of saidcompartments, wherein each water level sensor is configured tocontinuously measure an upper level of water in a compartment.
 4. Themethod of claim 3, wherein each of said oil level sensors comprises abuoyant float assembly, machine vision assembly or combinations thereof.5. The method of claim 3, wherein each of said water level sensorscomprises a buoyant float assembly, machine vision assembly orcombinations thereof.
 6. The method of claim 1, wherein said vesselfurther comprises at least one sight glass disposed on said vessel foreach of said compartments.
 7. The method of claim 6, wherein said upperand lower levels of oil and water are measured using said sight glass.8. A method for separating and measuring flow rate of an immiscible wellproduction fluid mixture including oil and water over a predeterminedtime period, without metering said fluid, comprising: a) continuouslyintroducing said immiscible well production fluid mixture into aseparation and measurement assembly comprising a vessel having aninternal chamber, wherein said internal chamber further comprises aplurality of compartments having predetermined dimensions; b) separatinggaseous components from liquid components of said production fluids; c)determining volume of oil in each of said compartments at a first timeat the start of said time period, comprising: (i) measuring upper andlower levels of oil in each of said compartments at said first time;(ii) volumetrically calculating volumes of oil in each of saidcompartments using said measured oil levels and said predetermineddimensions of said compartments at said first time; (iii) summing saidcalculated volumes of oil from each of said compartments at said firsttime; d) determining volumes of oil in each of said compartments at asecond time at the end of said time period, comprising: (i) measuringupper and lower levels of oil in each of said compartments at saidsecond time; (ii) volumetrically calculating volumes of oil in each ofsaid compartments using said measured oil levels and said predetermineddimensions of said compartments at said second time; (iii) summing saidcalculated volumes of oil from each of said compartments at said secondtime; and e) deducting said sum of calculated oil volumes at said secondtime from said sum of calculated oil volumes at said first time.
 9. Themethod of claim 8, further comprising: a) determining volumes of waterin each of said compartments at said first time, comprising: (i)measuring upper and lower levels of water in each of said compartmentsat a first time; (ii) volumetrically calculating volumes of water ineach of said compartments using said measured water levels and saidpredetermined dimensions of said compartments at said first time; (iii)summing said calculated volumes of water from each of said compartmentsat said first time; b) determining volumes of water in each of saidcompartments at a second time at the end of said time period,comprising: (i) measuring upper and lower levels of water in each ofsaid compartments at said second time; (ii) volumetrically calculatingvolumes of water in each of said compartments using said measured waterlevels and said predetermined dimensions of said compartments at saidsecond time; (iii) summing said calculated volumes of water from each ofsaid compartments at said second time; and c) deducting said sum ofcalculated water volumes at said second time from said sum of calculatedwater volumes at said first time.
 10. The method of claim 8, whereinsaid separation and measurement assembly further comprises at least oneoil level sensor in each of said compartments, wherein each oil levelsensor is configured to continuously measure an upper level of oil in acompartment.
 11. The method of claim 9, wherein said separation andmeasurement assembly further comprises at least one water level sensorin each of said compartments, wherein each water level sensor isconfigured to continuously measure an upper level of water in acompartment.
 12. The method of claim 10, wherein each of said oil levelsensors comprises a buoyant float assembly, machine vision assembly orcombinations thereof.
 13. The method of claim 11, wherein each of saidwater level sensors comprises a buoyant float assembly, machine visionassembly or combinations thereof.
 14. The method of claim 9, whereinsaid vessel further comprises at least one sight glass disposed on saidvessel for each of said compartments.
 15. A method for separating andmeasuring flow rate of an immiscible well production fluid mixtureincluding oil and water over a predetermined time period, withoutmetering said fluid, comprising: a) continuously introducing saidimmiscible well production fluid mixture into a separation andmeasurement assembly comprising a vessel having an internal chamber,wherein said internal chamber further comprises a plurality ofcompartments having predetermined dimensions; b) separating gaseouscomponents from liquid components of said production fluids; c)determining volumes of oil in each of said compartments at the start ofsaid time period, comprising: (i) measuring upper and lower levels ofoil in each of said compartments at the start of said time period; (ii)volumetrically calculating volumes of oil in each of said compartmentsusing said measured oil levels and said predetermined dimensions of saidcompartments at the start of said time period; (iii) summing saidcalculated volumes of oil from each of said compartments at the start ofsaid time period; d) dumping oil from at least one of said compartments;e) determining volume of oil dumped from said at least one compartmentat a second time immediately following said dumping comprising: i)measuring upper and lower levels of oil in each of said compartments atsaid second time; ii) volumetrically calculating volumes of oil in eachof said compartments using said measured oil levels and saidpredetermined dimensions of said compartments at said second time; iii)summing said calculated volumes of oil from each of said compartments atsaid second time; iv) deducting said sum of calculated oil volumes atsaid second time from said sum of calculated oil volumes at said firsttime; f) determining volumes of oil in each of said compartments at theend of said time period, comprising: (i) measuring upper and lowerlevels of oil in each of said compartments at the end of said timeperiod; (ii) volumetrically calculating volumes of oil in each of saidcompartments using said measured oil levels and said predetermineddimensions of said compartments at the end of said time period; (iii)summing said calculated volumes of oil from each of said compartments atthe end of said time period; g) calculating the difference between saidsum of calculated oil volumes at the end of said time period and saidsum of calculated oil volumes at the beginning of said time period, andadding said dumped volume of oil to said difference.
 16. The method ofclaim 15, further comprising: a) determining volumes of water in each ofsaid compartments at the start of said time period, comprising: (i)measuring upper and lower levels of water in each of said compartmentsat the start of said time period; (ii) volumetrically calculatingvolumes of water in each of said compartments using said measured waterlevels and said predetermined dimensions of said compartments at thestart of said time period; (iii) summing said calculated volumes ofwater from each of said compartments at the start of said time period;b) dumping water from at least one of said compartments; c) determiningvolume of water dumped from said at least one compartment at a secondtime immediately following said dumping comprising: (i) measuring upperand lower levels of water in each of said compartments at said secondtime; (ii) volumetrically calculating volumes of water in each of saidcompartments using said measured water levels and said predetermineddimensions of said compartments at said second time; (iii) summing saidcalculated volumes of water from each of said compartments at saidsecond time; (iv) deducting said sum of calculated water volumes at saidsecond time from said sum of calculated water volumes at said firsttime; d) determining volumes of water in each of said compartments atthe end of said time period, comprising: (i) measuring upper and lowerlevels of water in each of said compartments at the end of said timeperiod; (ii) volumetrically calculating volumes of water in each of saidcompartments using said measured water levels and said predetermineddimensions of said compartments at the end of said time period; (iii)summing said calculated volumes of water from each of said compartmentsat the end of said time period; e) calculating the difference betweensaid sum of calculated water volumes at the end of said time period andsaid sum of calculated water volumes at the beginning of said timeperiod, and adding said dumped volume of water to said difference. 17.The method of claim 15, wherein said separation and measurement assemblyfurther comprises at least one oil level sensor in each of saidcompartments, wherein each oil level sensor is configured tocontinuously measure an upper level of oil in a compartment.
 18. Themethod of claim 16, wherein said separation and measurement assemblyfurther comprises at least one water level sensor in each of saidcompartments, wherein each water level sensor is configured tocontinuously measure an upper level of water in a compartment.
 19. Themethod of claim 17, wherein each of said oil level sensors comprises abuoyant float assembly, machine vision assembly or combinations thereof.20. The method of claim 18, wherein each of said water level sensorscomprises a buoyant float assembly, machine vision assembly orcombinations thereof.
 21. A method for separating and measuring volumeof at least one component of an immiscible well production fluid mixtureincluding oil and water, without metering said fluid, comprising: a)continuously introducing said immiscible well production fluid mixtureinto a separation and measurement assembly comprising a vessel having aninternal chamber, wherein said internal chamber further comprises atleast one compartment having predetermined dimensions; b) separatinggaseous components from liquid components of said production fluids; c)measuring upper and lower levels of oil in said at least one compartmentat a first time; and d) volumetrically calculating volume of oil in saidat least one compartment using said measured oil levels and saidpredetermined dimensions of said at least one compartment at said firsttime.
 22. The method of claim 21, further comprising: a) measuring upperand lower levels of water in said at least one compartment at a firsttime; and b) volumetrically calculating volume of water in said at leastone compartment using said measured water levels and said predetermineddimensions of said compartment at said first time.
 23. The method ofclaim 21, wherein said separation and measurement assembly furthercomprises at least one oil level sensor in said at least onecompartment, wherein said at least one oil level sensor is configured tocontinuously measure an upper level of oil in said at least onecompartment.
 24. The method of claim 22, wherein said separation andmeasurement assembly further comprises at least one water level sensorin said at least one compartment, wherein said at least one water levelsensor is configured to continuously measure an upper level of water insaid at least one compartment.